Note: Descriptions are shown in the official language in which they were submitted.
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USE OF DOWNHOLE PRESSURE MEASUREMENTS WHILE
DRILLING TO DETECT AND MITIGATE INFLUXES
TECHNICAL FIELD
This disclosure relates generally to equipment utilized
and operations performed in conjunction with drilling a
subterranean well and, in one example described below, more
particularly provides for use of downhole pressure
measurements while drilling to detect and mitigate influxes.
BACKGROUND
A hydraulics model can be used to control a drilling
operation, for example, in managed pressure, underbalanced,
overbalanced or controlled pressure drilling. Typically, an
objective is to maintain wellbore pressure at a desired
value during the drilling operation. Unfortunately, an
influx into a wellbore during drilling can disrupt normal
drilling operations, and if left unchecked can lead to
hazardous conditions.
Therefore, it will be appreciated that improvements are
continually needed in the art of detecting and mitigating
influxes during drilling operations.
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BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a representative partially cross-sectional
view of a well drilling system and associated method which
can embody principles of this disclosure.
FIG. 2 is a representative schematic view of another
example of the well drilling system and method.
FIG. 3 is a representative schematic view of a pressure
and flow control system which may be used with the system
and method of FIGS. 1 & 2.
FIG. 4 is a representative drilling log, in which an
influx event is recorded.
FIG. 5 is a representative flowchart for a method of
detecting and mitigating an influx.
DETAILED DESCRIPTION
Representatively illustrated in FIG. 1 is a well
drilling system 10 and associated method which can embody
principles of this disclosure. However, it should be clearly
understood that the system 10 and method are merely one
example of an application of the principles of this
disclosure in practice, and a wide variety of other examples
are possible. Therefore, the scope of this disclosure is not
limited at all to the details of the system 10 and method
described herein and/or depicted in the drawings.
In the FIG. 1 example, a wellbore 12 is drilled by
rotating a drill bit 14 on an end of a drill string 16.
Drilling fluid 18, commonly known as mud, is circulated
downward through the drill string 16, out the drill bit 14
and upward through an annulus 20 formed between the drill
string and the wellbore 12, in order to cool the drill bit,
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lubricate the drill string, remove cuttings and provide a
measure of bottom hole pressure control. A non-return valve
21 (typically a flapper-type check valve) prevents flow of
the drilling fluid 18 upward through the drill string 16
(e.g., when connections are being made in the drill string).
Control of wellbore pressure is very important in
managed pressure drilling, and in other types of drilling
operations. Preferably, the wellbore pressure is precisely
controlled to prevent excessive loss of fluid into the earth
formation surrounding the wellbore 12, undesired fracturing
of the formation, undesired influx of formation fluids into
the wellbore, etc.
In typical managed pressure drilling, it is desired to
maintain the wellbore pressure just slightly greater than a
pore pressure of the formation penetrated by the wellbore,
without exceeding a fracture pressure of the formation. This
technique is especially useful in situations where the
margin between pore pressure and fracture pressure is
relatively small.
In typical underbalanced drilling, it is desired to
maintain the wellbore pressure somewhat less than the pore
pressure, thereby obtaining a controlled influx of fluid
from the formation. In typical overbalanced drilling, it is
desired to maintain the wellbore pressure somewhat greater
than the pore pressure, thereby preventing (or at least
mitigating) influx of fluid from the formation.
Nitrogen or another gas, or another lighter weight
fluid, may be added to the drilling fluid 18 for pressure
control. This technique is useful, for example, in
underbalanced drilling operations.
In the system 10, additional control over the wellbore
pressure is obtained by closing off the annulus 20 (e.g.,
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isolating it from communication with the atmosphere and
enabling the annulus to be pressurized at or near the
surface) using a rotating control device 22 (RCD). The RCD
22 seals about the drill string 16 above a wellhead 24.
Although not shown in FIG. 1, the drill string 16 would
extend upwardly through the RCD 22 for connection to, for
example, a rotary table (not shown), a standpipe line 26,
kelley (not shown), a top drive and/or other conventional
drilling equipment.
The drilling fluid 18 exits the wellhead 24 via a wing
valve 28 in communication with the annulus 20 below the RCD
22. The fluid 18 then flows through mud return lines 30, 73
to a choke manifold 32, which includes redundant chokes 34
(only one of which might be used at a time). Backpressure is
applied to the annulus 20 by variably restricting flow of
the fluid 18 through the operative choke(s) 34.
In other examples, flow control devices other than
chokes 34 may be used for applying backpressure to the
annulus 20. For example, a valve or other type of flow
control device can be used to restrict flow or divert flow,
so that the backpressure applied to the annulus 20 is
regulated.
In the FIG. 1 example, the greater the restriction to
flow through the choke 34, the greater the backpressure
applied to the annulus 20. Thus, downhole pressure (e.g.,
pressure at the bottom of the wellbore 12, pressure at a
downhole casing shoe, pressure at a particular formation or
zone, etc.) can be conveniently regulated by varying the
backpressure applied to the annulus 20. A hydraulics model
can be used, as described more fully below, to determine a
pressure applied to the annulus 20 at or near the surface
which will result in a desired downhole pressure, so that an
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operator (or an automated control system) can readily
determine how to regulate the pressure applied to the
annulus at or near the surface (which can be conveniently
measured) in order to obtain the desired downhole pressure.
Pressure applied to the annulus 20 can be measured at
or near the surface via a variety of pressure sensors 36,
38, 40, each of which is in communication with the annulus.
Pressure sensor 36 senses pressure below the RCD 22, but
above a blowout preventer (BOP) stack 42. Pressure sensor 38
senses pressure in the wellhead below the BOP stack 42.
Pressure sensor 40 senses pressure in the mud return lines
30, 73 upstream of the choke manifold 32.
Another pressure sensor 44 senses pressure in the
standpipe line 26. Yet another pressure sensor 46 senses
pressure downstream of the choke manifold 32, but upstream
of a separator 48, shaker 50 and mud pit 52. Additional
sensors include temperature sensors 54, 56, Coriolis
flowmeter 58, and flowmeters 62, 64, 66.
Not all of these sensors are necessary. For example,
the system 10 could include only two of the three flowmeters
62, 64, 66. However, input from all available sensors can be
useful to the hydraulics model in determining what the
pressure applied to the annulus 20 should be during the
drilling operation.
Other sensor types may be used, if desired. For
example, it is not necessary for the flowmeter 58 to be a
Coriolis flowmeter, since a turbine flowmeter, acoustic
flowmeter, or another type of flowmeter could be used
instead.
In addition, the drill string 16 may include its own
sensors 60, for example, to directly measure downhole
pressure. Such sensors 60 may be of the type known to those
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skilled in the art as pressure while drilling (PWD),
measurement while drilling (MWD) and/or logging while
drilling (LWD). These drill string sensor systems generally
provide at least pressure measurement, and may also provide
temperature measurement, detection of drill string
characteristics (such as vibration, weight on bit, stick-
slip, etc.), formation characteristics (such as resistivity,
density, etc.) and/or other measurements. Various forms of
wired or wireless telemetry (acoustic, pressure pulse,
electromagnetic, etc.) may be used to transmit the downhole
sensor measurements to the surface.
Additional sensors could be included in the system 10,
if desired. For example, another flowmeter 67 could be used
to measure the rate of flow of the fluid 18 exiting the
wellhead 24, another Coriolis flowmeter (not shown) could be
interconnected directly upstream or downstream of a rig mud
pump 68, etc.
Fewer sensors could be included in the system 10, if
desired. For example, the output of the rig mud pump 68
could be determined by counting pump strokes, instead of by
using the flowmeter 62 or any other flowmeters.
Note that the separator 48 could be a 3 or 4 phase
separator, or a mud gas separator (sometimes referred to as
a "poor boy degasser"). However, the separator 48 is not
necessarily used in the system 10.
The drilling fluid 18 is pumped through the standpipe
line 26 and into the interior of the drill string 16 by the
rig mud pump 68. The pump 68 receives the fluid 18 from the
mud pit 52 and flows it via a standpipe manifold 70 to the
standpipe 26. The fluid 18 then circulates downward through
the drill string 16, upward through the annulus 20, through
the mud return lines 30, 73, through the choke manifold 32,
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and then via the separator 48 and shaker 50 to the mud pit
52 for conditioning and recirculation.
Note that, in the system 10 as so far described above,
the choke 34 cannot be used to control backpressure applied
to the annulus 20 for control of the downhole pressure,
unless the fluid 18 is flowing through the choke. In
conventional overbalanced drilling operations, a lack of
fluid 18 flow will occur, for example, whenever a connection
is made in the drill string 16 (e.g., to add another length
of drill pipe to the drill string as the wellbore 12 is
drilled deeper), and the lack of circulation will require
that downhole pressure be regulated solely by the density of
the fluid 18.
In the system 10, however, flow of the fluid 18 through
the choke 34 can be maintained, even though the fluid does
not circulate through the drill string 16 and annulus 20,
while a connection is being made in the drill string. Thus,
pressure can still be applied to the annulus 20 by
restricting flow of the fluid 18 through the choke 34, even
though a separate backpressure pump may not be used.
When fluid 18 is not circulating through drill string
16 and annulus 20 (e.g., when a connection is made in the
drill string), the fluid is flowed from the pump 68 to the
choke manifold 32 via a bypass line 72, 75. Thus, the fluid
18 can bypass the standpipe line 26, drill string 16 and
annulus 20, and can flow directly from the pump 68 to the
mud return line 30, which remains in communication with the
annulus 20. Restriction of this flow by the choke 34 will
thereby cause pressure to be applied to the annulus 20 (for
example, in typical managed pressure drilling).
As depicted in FIG. 1, both of the bypass line 75 and
the mud return line 30 are in communication with the annulus
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20 via a single line 73. However, the bypass line 75 and the
mud return line 30 could instead be separately connected to
the wellhead 24, for example, using an additional wing valve
(e.g., below the RCD 22), in which case each of the lines
30, 75 would be directly in communication with the annulus
20.
Although this might require some additional piping at
the rig site, the effect on the annulus pressure would be
essentially the same as connecting the bypass line 75 and
the mud return line 30 to the common line 73. Thus, it
should be appreciated that various different configurations
of the components of the system 10 may be used, and still
remain within the scope of this disclosure.
Flow of the fluid 18 through the bypass line 72, 75 is
regulated by a choke or other type of flow control device
74. Line 72 is upstream of the bypass flow control device
74, and line 75 is downstream of the bypass flow control
device.
Flow of the fluid 18 through the standpipe line 26 is
substantially controlled by a valve or other type of flow
control device 76. Since the rate of flow of the fluid 18
through each of the standpipe and bypass lines 26, 72 is
useful in determining how wellbore pressure is affected by
these flows, the flowmeters 64, 66 are depicted in FIG. 1 as
being interconnected in these lines.
However, the rate of flow through the standpipe line 26
could be determined even if only the flowmeters 62, 64 were
used, and the rate of flow through the bypass line 72 could
be determined even if only the flowmeters 62, 66 were used.
Thus, it should be understood that it is not necessary for
the system 10 to include all of the sensors depicted in FIG.
1 and described herein, and the system could instead include
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additional sensors, different combinations and/or types of
sensors, etc.
In the FIG. 1 example, a bypass flow control device 78
and flow restrictor 80 may be used for filling the standpipe
line 26 and drill string 16 after a connection is made in
the drill string, and for equalizing pressure between the
standpipe line and mud return lines 30, 73 prior to opening
the flow control device 76. Otherwise, sudden opening of the
flow control device 76 prior to the standpipe line 26 and
drill string 16 being filled and pressurized with the fluid
18 could cause an undesirable pressure transient in the
annulus 20 (e.g., due to flow to the choke manifold 32
temporarily being lost while the standpipe line and drill
string fill with fluid, etc.).
By opening the standpipe bypass flow control device 78
after a connection is made, the fluid 18 is permitted to
fill the standpipe line 26 and drill string 16 while a
substantial majority of the fluid continues to flow through
the bypass line 72, thereby enabling continued controlled
application of pressure to the annulus 20. After the
pressure in the standpipe line 26 has equalized with the
pressure in the mud return lines 30, 73 and bypass line 75,
the flow control device 76 can be opened, and then the flow
control device 74 can be closed to slowly divert a greater
proportion of the fluid 18 from the bypass line 72 to the
standpipe line 26.
Before a connection is made in the drill string 16, a
similar process can be performed, except in reverse, to
gradually divert flow of the fluid 18 from the standpipe
line 26 to the bypass line 72 in preparation for adding more
drill pipe to the drill string 16. That is, the flow control
device 74 can be gradually opened to slowly divert a greater
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proportion of the fluid 18 from the standpipe line 26 to the
bypass line 72, and then the flow control device 76 can be
closed.
Note that the flow control device 78 and flow
restrictor 80 could be integrated into a single element
(e.g., a flow control device having a flow restriction
therein), and the flow control devices 76, 78 could be
integrated into a single flow control device 81 (e.g., a
single choke which can gradually open to slowly fill and
pressurize the standpipe line 26 and drill string 16 after a
drill pipe connection is made, and then open fully to allow
maximum flow while drilling).
However, since typical conventional drilling rigs are
equipped with the flow control device 76 in the form of a
valve in the standpipe manifold 70, and use of the standpipe
valve is incorporated into usual drilling practices, the
individually operable flow control devices 76, 78 preserve
the use of the flow control device 76. The flow control
devices 76, 78 are at times referred to collectively below
as though they are the single flow control device 81, but it
should be understood that the flow control device 81 can
include the individual flow control devices 76, 78.
Another example is representatively illustrated in FIG.
2. In this example, the flow control device 76 is connected
upstream of the rig's standpipe manifold 70. This
arrangement has certain benefits, such as, no modifications
are needed to the rig's standpipe manifold 70 or the line
between the manifold and the kelley, the rig's standpipe
bleed valve 82 can be used to vent the standpipe 26 as in
normal drilling operations (no need to change procedure by
the rig's crew), etc.
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The flow control device 76 can be interconnected
between the rig pump 68 and the standpipe manifold 70 using,
for example, quick connectors 84 (such as, hammer unions,
etc.). This will allow the flow control device 76 to be
conveniently adapted for interconnection in various rigs'
pump lines.
A specially adapted fully automated flow control device
76 (e.g., controlled automatically by the controller 96
depicted in FIG. 3) can be used for controlling flow through
the standpipe line 26, instead of using the conventional
standpipe valve in a rig's standpipe manifold 70. The entire
flow control device 81 can be customized for use as
described herein (e.g., for controlling flow through the
standpipe line 26 in conjunction with diversion of fluid 18
between the standpipe line and the bypass line 72 to thereby
control pressure in the annulus 20, etc.), rather than for
conventional drilling purposes.
In the FIG. 2 example, a remotely controllable valve or
other flow control device 160 is optionally used to divert
flow of the fluid 18 from the standpipe line 26 to the mud
return line 30 downstream of the choke manifold 32, in order
to transmit signals, data, commands, etc. to downhole tools
(such as the FIG. 1 bottom hole assembly including the
sensors 60, other equipment, including mud motors,
deflection devices, steering controls, etc.). The device 160
is controlled by a telemetry controller 162, which can
encode information as a sequence of flow diversions
detectable by the downhole tools (e.g., a certain decrease
in flow through a downhole tool will result from a
corresponding diversion of flow by the device 160 from the
standpipe line 26 to the mud return line 30).
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A suitable telemetry controller and a suitable remotely
operable flow control device are provided in a GEO-SPAN(TM)
system marketed by Halliburton Energy Services, Inc. of
Houston, Texas USA. The telemetry controller 162 can be
connected to an INSITE(TM) system or other acquisition and
control interface 94 in the control system 90. However,
other types of telemetry controllers and flow control
devices may be used in keeping with the scope of this
disclosure.
Note that each of the flow control devices 74, 76, 78
and chokes 34 are preferably remotely and automatically
controllable to maintain a desired downhole pressure by
maintaining a desired annulus pressure at or near the
surface. However, any one or more of these flow control
devices 74, 76, 78 and chokes 34 could be manually
controlled, in keeping with the scope of this disclosure.
A pressure and flow control system 90 which may be used
in conjunction with the system 10 and associated methods of
FIGS. 1 & 2 is representatively illustrated in FIG. 3. The
control system 90 is preferably fully automated, although
some human intervention may be used, for example, to
safeguard against improper operation, initiate certain
routines, update parameters, etc.
The control system 90 includes a hydraulics model 92, a
data acquisition and control interface 94 and a controller
96 (such as a programmable logic controller or PLC, a
suitably programmed computer, etc.). Although these elements
92, 94, 96 are depicted separately in FIG. 3, any or all of
them could be combined into a single element, or the
functions of the elements could be separated into additional
elements, other additional elements and/or functions could
be provided, etc.
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The hydraulics model 92 is used in the control system
90 to determine the desired annulus pressure at or near the
surface to achieve a desired downhole pressure. Data such as
well geometry, fluid properties and offset well information
(such as geothermal gradient and pore pressure gradient,
etc.) are utilized by the hydraulics model 92 in making this
determination, as well as real-time sensor data acquired by
the data acquisition and control interface 94.
Thus, there is a continual two-way transfer of data and
information between the hydraulics model 92 and the data
acquisition and control interface 94. It is important to
appreciate that the data acquisition and control interface
94 operates to maintain a substantially continuous flow of
real-time data from the sensors 44, 54, 66, 62, 64, 60, 58,
46, 36, 38, 40, 56, 67 to the hydraulics model 92, so that
the hydraulics model has the information it needs to adapt
to changing circumstances and to update the desired annulus
pressure, and the hydraulics model operates to supply the
data acquisition and control interface substantially
continuously with a value for the desired annulus pressure.
A suitable hydraulics model for use as the hydraulics
model 92 in the control system 90 is REAL TIME HYDRAULICS
(TM) or GB SETPOINT (TM) marketed by Halliburton Energy
Services, Inc. of Houston, Texas USA. Another suitable
hydraulics model is provided under the trade name IRIS (TM),
and yet another is available from SINTEF of Trondheim,
Norway. Any suitable hydraulics model may be used in the
control system 90 in keeping with the principles of this
disclosure.
A suitable data acquisition and control interface for
use as the data acquisition and control interface 94 in the
control system 90 are SENTRY(TM) and INSITE(TM) marketed by
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Halliburton Energy Services, Inc. Any suitable data
acquisition and control interface may be used in the control
system 90 in keeping with the principles of this disclosure.
The controller 96 operates to maintain a desired
setpoint annulus pressure by controlling operation of the
mud return choke 34 and other devices. When an updated
desired annulus pressure is transmitted from the data
acquisition and control interface 94 to the controller 96,
the controller uses the desired annulus pressure as a
setpoint and controls operation of the choke 34 in a manner
(e.g., increasing or decreasing flow resistance through the
choke as needed) to maintain the setpoint pressure in the
annulus 20. The choke 34 can be closed more to increase flow
resistance, or opened more to decrease flow resistance.
Maintenance of the setpoint pressure is accomplished by
comparing the setpoint pressure to a measured annulus
pressure (such as the pressure sensed by any of the sensors
36, 38, 40), and decreasing flow resistance through the
choke 34 if the measured pressure is greater than the
setpoint pressure, and increasing flow resistance through
the choke if the measured pressure is less than the setpoint
pressure. Of course, if the setpoint and measured pressures
are the same, then no adjustment of the choke 34 is
required. This process is preferably automated, so that no
human intervention is required, although human intervention
may be used, if desired.
The controller 96 may also be used to control operation
of the standpipe flow control devices 76, 78 and the bypass
flow control device 74. The controller 96 can, thus, be used
to automate the processes of diverting flow of the fluid 18
from the standpipe line 26 to the bypass line 72 prior to
making a connection in the drill string 16, then diverting
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flow from the bypass line to the standpipe line after the
connection is made, and then resuming normal circulation of
the fluid 18 for drilling. Again, no human intervention may
be required in these automated processes, although human
intervention may be used if desired, for example, to
initiate each process in turn, to manually operate a
component of the system, etc.
Data validation and prediction techniques may be used
in the system 90 to guard against erroneous data being used,
to ensure that determined values are in line with predicted
values, etc. Suitable data validation and prediction
techniques are described in International Application No.
PCT/US11/59743, although other techniques may be used, if
desired.
When drilling in an open circulation system, pressure-
while-drilling (PWD) pressure measurement tools have been
used to monitor bottom hole pressures, and have been used to
detect wellbore events. With managed pressure drilling
(MPD) and the use of chokes 34 or other types of flow
control devices to maintain desired wellbore pressure, the
use of PWD measurements to detect events has been greatly
limited.
A calibration factor CF for adjusting a fluid friction
pressure calculated by the hydraulics model 92 can be given
by the following equation:
CF = (PWD psi - WHP - Hydrostatic)/model friction (1)
where PWD psi is the pressure measurement made by a PWD
tool (such as sensor 60) interconnected in the drill string
16, WHP is annulus pressure as measured at or near the
surface (e.g., at the wellhead 24), and Hydrostatic is the
static wellbore pressure (e.g., without circulation through
the drill string and annulus 20) at a location in the
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wellbore, due to a weight of a column of fluid 18 above the
location. Hydrostatic is calculated, based on a measured
density of the fluid 18 and a measured true vertical depth
of the fluid column above the wellbore location.
The model friction is calculated in real-time by the
hydraulics model 92. The calibration factor CF is applied to
the model friction (CF * model friction) to calculate the
actual friction pressure (Friction).
The numerator of the above equation (PWD psi - WHP -
Hydrostatic) under normal managed pressure drilling
conditions is a determination of the measured friction
pressure in the wellbore 12, and is a real-time value (each
of the terms in the numerator is available for use in the
equation in real-time). PWD data transmission frequency may
be several seconds to several minutes, and Equation (1) can
be applied to calculate the calibration factor CF each time
PWD data is received.
In normal circumstances, there should be very little
difference between the modeled and the measured friction
pressure (the denominator and numerator, respectively, in
the above equation), so the CF should be approximately 1. If
CF increases, this is an indicator that fluid friction in
the wellbore 12 is increasing (e.g., more cuttings in the
wellbore, partial collapse of the wellbore, etc.). If CF
begins to decrease, this is an indication of decreasing
fluid friction, which could be the result of gas lift (e.g.,
gas expanding in the annulus 20 as it flows upward to the
surface, thereby reducing the effective density of the
annulus fluid 18 column).
In managed pressure drilling (e.g., drilling with the
annulus closed to the atmosphere at or near the surface, and
with pressure in the annulus 20 being regulated to thereby
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regulate downhole pressure), one or more chokes 34 which
restrict flow of the fluid 18 from the annulus may be
controlled using the following equation:
WHP = Desired ¨ Friction - Hydrostatic (2)
where Desired is the desired pressure at any location
in a wellbore (e.g., at a bottom or distal end of the
wellbore, at a casing shoe, at an under-pressured zone
penetrated by the wellbore, etc.), and Friction is the
pressure due to fluid friction in the annulus 20 (Friction =
CF * model friction, as discussed above).
The choke(s) 34 may be opened further (resulting in
less restriction to flow) if the WHP is greater than that
given by the above equation, and the choke(s) may be closed
further (resulting in more restriction to flow) if the WHP
is less than that given by the above equation. Use of
appropriate values for the terms in Equation (2) for
calculating the WHP is, therefore, very important for
controlling operation of the choke(s) 34, or otherwise
precisely controlling wellbore 12 pressure.
It has been discovered that, after an influx occurs in
a situation where a PWD tool or other pressure sensor 60 is
part of the drill string 16, the hydraulics model 92 will
adjust the CF (e.g., applying Equation (1) above) to
maintain a desired wellbore pressure (see the log example
depicted in FIG. 4). When the control system 90 is
controlling the wellbore 12 pressure with automation (e.g.,
the choke(s) 34 are automatically controlled to maintain the
desired wellbore pressure) and with the hydraulics model 92
operating, the CF can decrease rapidly (e.g., as low as
.001) when such an influx occurs.
Such a low CF is not correct, since with any
circulating fluid 18 there has to be friction in the
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wellbore 12. The error in Equation 1 during an influx, then,
is in the Hydrostatic term (e.g., in the static fluid
density used to calculate the hydrostatic pressure). During
an influx, as gas migrates up the annulus 20, and the influx
fluid (e.g., gas condensate, etc.) transitions from a single
phase to a multiphase fluid, the hydrostatic pressure in the
annulus 20 will decrease.
To use PWD for kick detection and prevention in MPD
operations, an identification of the kick (influx) could be
through real-time monitoring, trend analysis applications,
and/or neural net analysis, etc., of the hydraulics model 92
calculated calibration factor CF. Other techniques for
identification of the influx from the characteristics of the
CF (e.g., assessment of a slope, second order derivative,
etc. of the CF) could be used, if desired. During the real-
time analysis of the CF, if at some time a predetermined
regression or aggression occurs, an alarm could be
triggered, and the hydraulics model 92 could begin
correcting the Hydrostatic term of the control algorithm to
prevent any further influx.
The following is an algorithm which, applied as
discussed more fully below, will prevent the influx from
increasing:
Adjusted MW = Prior MW - ((Prior Friction - Observed
Friction)/(.052 * TVD)) (3)
where Adjusted MW is an adjusted mud weight (fluid 18
density) for use in calculating the Hydrostatic term, Prior
MW is a next previous calculated or measured fluid density,
Prior Friction is a next previous modeled friction pressure,
Observed Friction is a currently calculated friction
pressure (e.g., using Equation 2), and TVD is true vertical
depth. Note that the .052 term is for converting mud weight
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in pounds per gallon to pounds per square inch (when
multiplied by TVD in feet). This conversion factor will
change if other units are used.
Applied repeatedly, this Equation 3 will adjust the
Hydrostatic term until the CF substantially equals 1. Once
the influx is out of the annulus 20, the CF will begin to
increase and, using the same equation, the Hydrostatic term
will be appropriately adjusted.
As soon as the influx has been identified (e.g., using
real-time monitoring, trend analysis applications, neural
net analysis, etc.), Equation 3 can be repeatedly applied to
gradually decrease the Hydrostatic term of Equation 1. In
actual practice, this will result in a gradual decrease in
the Hydrostatic term of Equation 1, until the CF term
stabilizes and begins increasing again.
In the FIG. 4 example log, the calibration factor CF
decreases to near zero when an influx into a wellbore
occurs. Note that the decrease in the CF begins in advance
of a significant increase in pit volume, and in advance of
an increase in a 3P gas reading. This (the influx and
resulting CF decrease) is a situation which can be avoided
using the principles described herein.
Note that the mud weight MW remains unchanged in the
FIG. 4 log, even after the influx has occurred, the pit
volume has increased, and increased gas has been detected at
the surface. This lack of adjustment to the fluid density
after the influx, with the consequent reduction in the
calibration factor CF, is mitigated by use of the principles
described herein.
Since the decrease in the calibration factor CF
depicted in the FIG. 4 log precedes the pit volume increase
and the increased gas reading at the surface, it will be
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appreciated that this CF decrease can serve as an early
indicator of the influx occurring. Using the real-time
monitoring, trend analysis applications, neural net analysis
techniques, etc., mentioned above, such influx-indicating CF
decreases can be readily identified, so that an operator can
be alerted, remedial actions (such as use of Equation 3
above to modify the Hydrostatic term, etc.) can be taken,
and further influxes can be prevented.
This approach to early kick (influx) detection and
prevention is markedly different from prior approaches.
Kick detection with MPD has generally been by monitoring
choke adjustment and mass flow differences (mass flow out of
the well minus mass flow into the well), which techniques
have heretofore yielded mixed results.
When measurements made by a PWD tool (or other downhole
pressure measurement device, such as, an MWD tool) are used
in the manner described above, the calibration factor CF can
be accurately determined, even if an influx results in a
change in the fluid density. This will allow for enhanced
wellbore pressure control, with the pressure measurement
tool (PWD, MWD, etc.) in the wellbore 12.
Referring additionally now to FIG. 5, an example
flowchart for a method 100 of detecting and mitigating an
influx into a wellbore 12 during drilling is
representatively illustrated. The method 100 may be used
with the well drilling system 10 and pressure and flow
control system 90 described above, or the method may be used
with other systems.
In step 102, the calibration factor CF is determined.
Equation 1 may be used to calculate the calibration factor
CF, based on measured wellbore 12 pressure (e.g., from
sensors 60, such as PWD or MWD tools), measured annulus 20
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pressure at or near the surface (WHP), hydrostatic pressure
calculated from measured fluid density and true vertical
depth, and a friction pressure from the hydraulics model 92.
Further description of the calibration factor CF is provided
in US Patent No. 8240398, assigned to the assignee of the
present application.
The calibration factor CF is used in step 104 to
calculate an actual friction pressure. The actual friction
pressure (Friction) is used to calculate a desired annulus
20 pressure at or near the surface (WHP) which will result
in a desired pressure at a location in the wellbore 12.
Equation 2 can be used for this purpose.
In step 106, the calibration factor CF determined in
step 102 is evaluated. As discussed above, a relatively high
value for the CF is indicative of increased fluid friction
in the annulus 20, for example, due to increased drill
cuttings, partial wellbore collapse, etc. A rapidly
decreasing CF is indicative of an influx into the wellbore.
Techniques known to those skilled in the art, such as, trend
analysis, a neural network, analysis of slope and/or second
order derivatives, etc., may be used in step 106 to identify
when an influx or other type of event is occurring, or has
occurred.
In step 108, a density of the fluid 18 is adjusted, in
order to mitigate the effects of an event indicated in step
106. For example, if an influx is indicated in step 106,
then in step 108, the fluid 18 density (e.g., mud weight MW)
can be incrementally decreased, so that the calculated
Hydrostatic term used in Equation 2 is also decreased.
Equation 3 can be used for this purpose. The decrease in
fluid 18 density corresponds to a decreased density in the
annulus 20 due to the influx, gas expansion, etc.
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Note that the actual density of the fluid 18 is not
decreased. Instead, the Hydrostatic term used in Equation 2
is incrementally decreased by decreasing the mud weight MW
used in calculation of the hydrostatic pressure, so that the
applied pressure (WHP in Equation 3) incrementally
increases.
This increased applied pressure WHP will eventually
prevent further influxes into the wellbore 12, at which
point the calibration factor CF will begin to increase and,
as a result of repeated application of steps 102, 104 and
108, the fluid density MW used for calculating the
Hydrostatic term in Equation 2 will increase. Eventually,
the calibration factor CF should level off at approximately
one, as conditions return to normal.
It may be desired to limit the increased applied WHP,
in order to, for example, prevent damage to a fragile or
sensitive formation. In that case, the Hydrostatic term in
Equation 2 may only be decreased by a predetermined amount,
and/or, a predetermined maximum level may be set for the
applied WHP, so that pressure in the wellbore 12 at a
certain location will not exceed a maximum level. A limit on
the applied WHP may also (or alternatively) be set in order
to prevent damage to equipment (such as, surface pressure
control and flow equipment).
If the evaluation of the calibration factor CF in step
106 (e.g., by trend analysis, a neural network, analysis of
slope and/or second order derivatives, etc.) indicates that
a substantial influx has entered the wellbore 12, and well
control procedures should begin, the fluid 18 can be
automatically diverted to rig well control equipment. For
example, in the FIG. 2 schematic, flow of the fluid 18 can
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be diverted from the choke manifold 32 to a rig choke
manifold (e.g., via the Choke Line).
In response to an increase in the calibration factor CF
(e.g., indicating increased drill cuttings, partial wellbore
collapse, etc.), the Hydrostatic term in Equation 2 could
instead be incrementally increased. This will result in less
pressure being applied to the wellbore 12 at or near the
surface, if desired, for example, to compensate for
increased drill cuttings volume in the annulus 20, etc. The
Hydrostatic term may be incrementally increased, until the
calibration factor CF begins decreasing.
It may now be fully appreciated that the above
disclosure provides significant advancements to the art of
wellbore pressure control. In one example described above, a
calibration factor CF is used to calculate fluid friction
pressure in a wellbore 12, and a decrease in the calibration
factor indicates that an influx has occurred. A fluid 18
density term can be incrementally changed in response to
detecting a predetermined change in the calibration factor
CF, in order to, for example, mitigate the effects of an
influx.
A well drilling method is provided to the art by the
above disclosure. In one example, the method can comprise:
drilling a wellbore 12, a fluid 18 circulating through the
wellbore 12 during the drilling; determining a calibration
factor CF which is applied to a modeled fluid friction
pressure; and controlling the drilling based at least in
part on a change in the calibration factor CF.
The modeled fluid friction pressure may be generated by
a hydraulics model 92.
An increase in the calibration factor CF can indicate
an increase in actual fluid friction in the wellbore 12. A
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decrease in the calibration factor CF can indicate a
decrease in hydrostatic pressure in the wellbore.
The method may include setting an alarm when the
calibration factor CF decreases below a predetermined level,
and/or when the calibration factor CF decreases at greater
than a predetermined rate.
The controlling step can include automatically
diverting flow of the fluid 18 to a rig choke manifold in
response to the change in the calibration factor CF.
The controlling step can include increasing pressure
applied to the wellbore 12 at or near the earth's surface,
in response to the change in the calibration factor CF. The
pressure increasing step may include increasing the pressure
applied to the wellbore to a predetermined maximum level.
The controlling step may include incrementally
decreasing a Hydrostatic term in the equation: WHP = Desired
¨ Friction ¨ Hydrostatic, where WHP is pressure applied to
the wellbore at or near the earth's surface, Desired is a
desired pressure at a wellbore location, Friction is fluid
friction in the wellbore, and Hydrostatic is hydrostatic
pressure at the location.
The incrementally decreasing step can include
incrementally decreasing the Hydrostatic term in response to
a decrease in the calibration factor CF.
The incrementally decreasing step may include
incrementally decreasing the Hydrostatic term, until the
calibration factor CF begins increasing, until the WHP term
reaches a predetermined maximum level, and/or until the
Hydrostatic term has been decreased a predetermined amount.
The controlling step can include, in response to an
increase in the calibration factor CF, incrementally
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increasing a Hydrostatic term in the equation: WHP = Desired
¨ Friction ¨ Hydrostatic, where WHP is pressure applied to
the wellbore at or near the earth's surface, Desired is a
desired pressure at a wellbore location, Friction is fluid
friction in the wellbore, and Hydrostatic is hydrostatic
pressure at the location. The Hydrostatic term may be
incrementally increased until the calibration factor CF
decreases.
A well drilling system 10 is also described above. In
one example, the system 10 can comprise a hydraulics model
92 which determines a modeled fluid friction pressure and a
calibration factor CF applied to the modeled friction
pressure; and a flow control device (such as choke 34) which
is automatically controlled in response to a change in the
calibration factor CF.
Although various examples have been described above,
with each example having certain features, it should be
understood that it is not necessary for a particular feature
of one example to be used exclusively with that example.
Instead, any of the features described above and/or depicted
in the drawings can be combined with any of the examples, in
addition to or in substitution for any of the other features
of those examples. One example's features are not mutually
exclusive to another example's features. Instead, the scope
of this disclosure encompasses any combination of any of the
features.
Although each example described above includes a
certain combination of features, it should be understood
that it is not necessary for all features of an example to
be used. Instead, any of the features described above can be
used, without any other particular feature or features also
being used.
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It should be understood that the various embodiments
described herein may be utilized in various orientations,
such as inclined, inverted, horizontal, vertical, etc., and
in various configurations, without departing from the
principles of this disclosure. The embodiments are described
merely as examples of useful applications of the principles
of the disclosure, which is not limited to any specific
details of these embodiments.
In the above description of the representative
examples, directional terms (such as "above," "below,"
"upper," "lower," etc.) are used for convenience in
referring to the accompanying drawings. However, it should
be clearly understood that the scope of this disclosure is
not limited to any particular directions described herein.
The terms "including," "includes," "comprising,"
"comprises," and similar terms are used in a non-limiting
sense in this specification. For example, if a system,
method, apparatus, device, etc., is described as "including"
a certain feature or element, the system, method, apparatus,
device, etc., can include that feature or element, and can
also include other features or elements. Similarly, the term
"comprises" is considered to mean "comprises, but is not
limited to."
Of course, a person skilled in the art would, upon a
careful consideration of the above description of
representative embodiments of the disclosure, readily
appreciate that many modifications, additions,
substitutions, deletions, and other changes may be made to
the specific embodiments, and such changes are contemplated
by the principles of this disclosure. For example,
structures disclosed as being separately formed can, in
other examples, be integrally formed and vice versa.
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The scope of the claims should not be limited by the preferred embodiments set
forth in the
examples, but should be give the broadest interpretation consistent with the
description as a
whole.
